Methods for replenishing particles screened from drilling fluids

ABSTRACT

Methods for selectively replacing the larger particles screened from a drilling fluid may include: circulating a drilling fluid comprising a base fluid and a plurality of particles through a wellbore penetrating a subterranean formation; passing the drilling fluid over a screen having a mesh size, thereby separating the plurality of particles into screened particles having a diameter greater than or equal to the mesh size and retained particles having a diameter smaller than the mesh size; adding a concentration of replenishment particles to the drilling fluid that comprises the base fluid and the retained particles, wherein a PSD of the replenishment particles has a d25 REP  greater than or equal to the mesh size; and re-circulating the drilling fluid including the replenishment particles back into the wellbore.

BACKGROUND

The exemplary embodiments described herein relate to methods forselectively replacing the larger particles screened from a drillingfluid.

Drilling fluids often include a plurality of particles that impartspecific properties (e.g., viscosity, mud weight, and the like) andcapabilities (e.g., wellbore strengthening) to the drilling fluid. Itshould be understood that the terms “particle” and “particulate,” asused in this disclosure, includes all known shapes of materials,including substantially spherical materials, fibrous materials,polygonal materials (such as cubic materials), and combinations thereof.

For example, weighting agents (i.e., particles having a specific gravitygreater than the base fluid of the drilling fluid) can be used toproduce drilling fluids with the desired mud weight (i.e., density),which affects the equivalent circulating density (“ECD”) of the drillingfluid. During drilling operations, for example, the ECD is oftencarefully monitored and controlled relative to the fracture gradient ofthe subterranean formation. Typically, the ECD during drilling is closeto the fracture gradient without exceeding it. When the ECD exceeds thefracture gradient, a fracture may form in the subterranean formation anddrilling fluid may be lost into the subterranean formation (oftenreferred to as lost circulation). In another example, lost circulationmaterials (“LCMs”) can be used to strengthen the wellbore and increasethe hoop stress around the wellbore, which allows for a higher ECD. TheLCMs incorporate into and plug microfractures extending from thewellbore, so as to mitigate fracture propagation and lost circulation.

The properties and capabilities that the particles impart on thedrilling fluid depend on, inter alia, the particle size distribution(“PSD”) of the particles, the specific gravity of the particles, theconcentration in the drilling fluid, and the like. In many instances, toachieve the desired properties in the drilling fluid, a mixture of typesof particles (e.g., varying by composition, shape, or the like) areused. Typically, the PSD of the particles in a drilling fluid is broad.

During many drilling operations, the drilling fluid is circulatedthrough the wellbore (e.g., down the drill string and back up throughthe annulus between the drill string and the wellbore), passed throughshakers to remove cuttings and debris produced during drilling, andrecirculated back into the wellbore. Shakers typically include one ormore screens with holes of a specific size (also referred to as the meshsize of the screen) to allow smaller particles and fluid through butretain larger particles for removal.

In removing the cuttings with shaker systems, some of the particles inthe drilling fluid that impart the desired properties and capabilitiesare also removed, thereby adversely altering the properties andcapabilities of the drilling fluid. To account for these changes,operators are required to add more particle additives (e.g., weightingagents and LCMs) back into the drilling fluid. However, the shakerremoves only the particles larger than the screen size, and the particleadditives mixed into the drilling fluid have a broad PSD. Therefore, tofully replace the concentration of larger particles, the concentrationof smaller particles increases, and the PSD remains changed. Further,the total volume percent of the particles in the drilling fluidincreases. The higher volume percent increases the viscosity and, as aconsequence of the particles' specific gravity, increases the density ofthe drilling fluid.

To combat the changes to fluid properties, operators often dilute thedrilling fluid and add additional additives to maintain the desiredfluid properties, such as emulsifiers and the like. Often the base fluidused to dilute the drilling fluid and the other additives are expensive.Additionally, a dilution approach increases the overall volume of fluidthat the operator has to handle or have stored on-site or shipped to thewell site, which further increases costs and complicates logistics,especially in off-shore drilling. However, while the viscosity may beaddressed to some degree by dilution, the PSD is still not the same asthe original PSD (i.e., the smaller diameter particles have a higherconcentration relative to the larger particles), which imparts differentproperties to the drilling fluid. Since drilling fluid is circulatedseveral times through the wellbore during drilling operations, thisproblem of maintaining drilling fluid properties and the consequences ofcommon dilution techniques can become cumulative and expensive.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of theembodiments, and should not be viewed as exclusive embodiments. Thesubject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to those skilled in the art and having the benefit of thisdisclosure.

FIG. 1 provides a diagram of at least one embodiment for replacingparticles screened from a drilling fluid.

FIG. 2 provides a theoretical trimodal diameter distribution for aplurality of particles.

FIG. 3 provides a theoretical trimodal diameter distribution for aplurality of particles.

FIG. 4 provides a drilling assembly suitable for use in conjunction withthe methods described herein.

DETAILED DESCRIPTION

The exemplary embodiments described herein relate to methods forselectively replacing the larger particles screened from a drillingfluid.

The methods described herein may mitigate significant changes in the PSDof particles in a drilling fluid during a drilling operation. In turn,the viscosity, mud weight, and wellbore strengthening capabilities,among other things, may vary minimally during the drilling operation.Further, the methods described herein do not effectively dilute thedrilling fluid and, therefore, do not exhibit the storage/transportationissues and cost associated with conventional methods that attempt tomitigate variations in the properties and capabilities of drillingfluids during a drilling operation.

The drilling fluids described herein comprise a base fluid and aplurality of particles having a particle size distribution (“PSD”). Asused herein the term, “particle size distribution” refers to a list ofvalues or a mathematical function that defines the relative amount byvolume of particles present within a fluid according to size. In someinstances, the particles described herein may have a PSD characterizedby a d10, a d25, a d50, a d75, and a d90. As used herein, the term “dn”(e.g., d10, d25, d50, d75, or d90) refers to a diameter for which n % byvolume of the particles have a smaller diameter. The dn for particlesdescribed herein may be determined by any suitable means (e.g., sieveanalysis, optical counting methods, image analysis, laser diffraction,light scattering, interaction with x-rays, interactions with neutrons,acoustic spectroscopy, sedimentation, elutriation, and the like). Oneskilled in the art would recognize that in the methods described hereinwhen the one plurality of particles is compared to another by PSD, dn,or both (e.g., d10_(SCR) vs d10_(REP)), the same technique fordetermining PSD, dn, or both is used for all pluralities of particlesbeing compared.

As described herein, the terms “particles” and “particulates” do notimply only a single type of particle, but rather encompasses a singletype of particle and mixtures of types of particles. As used herein, theterm “type of particle” indicates particles that are differentiated fromother particles, for example, by composition, shape, or PSD. That is,particles may comprise a first type of particles, a second type ofparticles, and a third type of particles that can each be differentiatedfrom the others by at least one of composition, shape, and PSD. Forexample, the first type of particles may be ground marble with a PSDwith a d25 of 2 microns, d50 of 7 microns, and d75 of 18 microns, thesecond type of particles may be ground marble having a PSD with a d25 of20 microns, d50 of 25 microns, and d75 of 30 microns, and the third typeof particles may be a resilient carbon-based material having a PSD witha d25 of 15 microns, d50 of 40 microns, and d75 of 55 microns.

FIG. 1 provides a diagram of at least one embodiment for replacingparticles screened from a drilling fluid. After circulating through thewellbore and to the surface, the drilling fluid may be passed through ascreen (e.g., in a shaker), so as to remove a portion of the firstplurality of particles having a diameter greater than or equal to themesh size of the screen, referred to herein as “screened particles.”Then, replenishment particles may be added to the material that passesthrough the screen (e.g., a wellbore fluid comprising the base fluid anda second portion of the first plurality of particles having a diameterless than the mesh size, referred to herein as “retained particles”).The drilling fluid comprising the base fluid, the retained particles,and the replenishment particles may then be introduced back into thewellbore. This procedure may be performed continuously and over a timeperiod such that a portion of the wellbore fluid is treated multipletimes through this method.

For clarity and brevity, the following abbreviations will be used assubscript to indicate which particles are referred to for PSD and dn:BS—the plurality of particles in the drilling fluid before screening,SCR—the screened particles, RET—the retained particles, REP—thereplenishment particles, and CMB—for the retained particles incombination with the replenishment particles.

In some embodiments, at least one the dn_(BS) may differ from thecorresponding dn_(CMB) by less than about 15% (e.g., about 1% to about15%, including subsets thereof). For example, the d50_(BS) may be within10% of the d50_(CMB). In another example, the d25_(BS), the d50_(BS),and the d75_(BS) may be within about 5%, about 10%, and about 15% of thed25_(CMB), the d50_(CMB), and the d75_(CMB), respectively. In yetanother example, the d10_(BS), the d50_(BS), and the d90_(BS) may bewithin about 5%, about 10%, and about 15% of the d10_(CMB), thed50_(CMB), and the d90_(CMB), respectively.

In some embodiments, the d25_(REP) may be greater than or equal to themesh size of the screen. In some embodiments, the d15_(REP) may begreater than or equal to the mesh size of the screen. In someembodiments, the d10_(REP) may be greater than or equal to the mesh sizeof the screen.

In some embodiments, the replenishment particles may be engineered tocorrespond to the screened particles. That is, the replenishmentparticles may comprise substantially the same types of particles in thesame proportions as in the screened particles. In some embodiments, atleast one of the dn_(SCR) may differ from the corresponding dn_(REP) byless than about 15% (e.g., about 1% to about 15%, including subsetsthereof). In some embodiments, the d25_(SCR), the d50_(SCR), and thed75_(SCR) may be within about 5% to about 15% of the d25_(REP), thed50_(REP), and the d75_(REP), respectively. In some embodiments, thed10_(SCR), the d50_(SCR), and the d90_(SCR) may be within about 5% toabout 15% of the d10_(REP), the d50_(REP), and the d90_(REP),respectively.

Screens suitable for use in conjunction with the methods and systemsdescribed herein may, in some embodiments, have a mesh size according tothe API screen numbers of Table 1 or the US sieve sizes of Table 2.

TABLE 1 API Screen Number d100 (microns) 35 >462.5-550.0 40 >390.0-462.545 >327.5-390.0 50 >275.0-327.5 60 >231.0-275.0 70 >196.0-231.080 >165.0-196.0 100 >137.5-165.0 120 >116.5-137.5 140  >98.0-116.5170 >82.5-98.0 200 >69.0-82.5 230 >58.0-69.0 270 >49.0-58.0325 >41.5-49.0 400 >35.0-41.5 450 >28.5-35.0

TABLE 2 API Screen Number d100 (microns) 3.5 5660 4 4760 5 4000 6 3360 72830 8 2380 10 2000 12 1680 14 1410 16 1190 18 1000 20 840 25 710 30 59035 500 40 420 45 350 50 297 60 250 70 210 80 177 100 149 120 125 140 105170 88 200 74 230 62 270 53 325 44 400 37

The rate of addition for the replenishment particles to the drillingfluid can be calculated from the concentration of the plurality ofparticles in the drilling fluid before screening, the PSD_(BS), and thedrilling fluid flow rate during screening. For example, the integral ofthe PSD_(BS) greater than the mesh size and the concentration may beused to determine the mass of particles removed per unit volume, whichcombined with the fluid flow rate may be used to determine a removalrate and the corresponding rate of addition that should be used.

In some embodiments, the plurality of the particles in the drillingfluid, the mesh sizes in the screening, and the replenishment particlesmay be chosen in combination to facilitate the methods described herein.For example, in some embodiments, a drilling fluid may comprise a basefluid and a plurality of particles having a multi-modal diameterdistribution such that the d75 of each mode is less than the d25 of thenext larger mode (or, in some instance, the d90 of each mode is lessthan the d10 of the next larger mode). In some instances, one screen ora series of screens may be used during drilling operations that have amesh size between the d75 of one mode and the d25 of the next largermode (or, in some instance, a mesh size between the d90 of one mode andthe d10 of the next larger mode). One skilled in the art would recognizeother combinations of dn's suitable for use in relation to multi-modaldiameter distributions and corresponding screen sizes (e.g., d75 withd10, d75 with d15, d90 with d25, d85 with d25, and so on).

By way of nonlimiting example, FIG. 2 provides a theoretical trimodaldiameter distribution for a plurality of particles that illustratesthree modes A, B, and C where mode A has a d90_(A) less than the d10_(B)of the next largest mode (mode B) and mode B has a d90_(B) less than thed10_(C) of the next largest mode (mode C). Further, FIG. 2 illustratesappropriately sized screens relative to each mode. That is screen size Yis between d90_(A) and d10_(B) and screen size Z is between d90_(B) andd10_(C).

In another example, FIG. 3 provides a theoretical bimodal diameterdistribution for a plurality of particles that illustrates two modes Aand B where mode A has a d75_(A) less than the d25_(B) of mode B.Further, FIG. 3 illustrates appropriate screen sizes Z between d75_(A)and d25_(B).

In some embodiments, the screen sizes may be chosen based on thediameter distribution of the plurality of particles in the drillingfluid. In some instances, the diameter distribution for the plurality ofparticles (e.g., the dn for each mode or the dn for each type ofparticle) may be chosen based on the screen size.

In some instances, each mode in a multi-modal PSD may correspond to atype of particle or plurality of particles that are initially separate.Then, the particles may be mixed together in the appropriate ratiosyield a multi-modal PSD to achieve the corresponding drilling fluidproperties (e.g., viscosity and mud weight). In some embodiments, thereplenishment particles may correspond to the particles of the mode ormodes having a d25 greater than the mesh size of the screen. In someembodiments, the replenishment particles may correspond to the particlesof the mode or modes having a d15 greater than the mesh size of thescreen. In some embodiments, the replenishment particles may correspondto the particles of the mode or modes having a d10 greater than the meshsize of the screen.

The methods disclosed herein apply to particles that include weightingagents, LCMs, and the like, and any combination thereof.

Generally, weighting agents have a specific gravity greater than thespecific gravity of the base fluid. Examples of weighting agents may beparticles that comprise barite, hematite, ilmenite, galena, manganeseoxide, iron oxide, magnesium tetroxide, magnetite, siderite, celesite,dolomite, manganese carbonate, insoluble polymeric materials, calciumcarbonate, marble, polyethylene, polypropylene, graphitic materials,silica, limestone, dolomite, a salt (e.g., salt crystals), shale,bentonite, kaolinite, sepiolite, illite, hectorite, organo-clays, andthe like. Combinations of these types of particles may be used in aweighting agent.

In some embodiments, LCMs may comprise particulates having a low aspectratio (e.g., less than about 3), fibers, or both. Suitable LCMs mayinclude those comprising materials suitable for use in a subterraneanformation, which may include, but are not limited to, sand, shale,ground marble, bauxite, ceramic materials, glass materials, metalpellets, high strength synthetic fibers, resilient graphitic carbon,cellulose flakes, wood, resins, polymer materials (crosslinked orotherwise), polytetrafluoroethylene materials, nut shell pieces, curedresinous particulates comprising nut shell pieces, seed shell pieces,cured resinous particulates comprising seed shell pieces, fruit pitpieces, cured resinous particulates comprising fruit pit pieces,composite materials, and any combination thereof. Suitable compositematerials may comprise a binder and a filler material wherein suitablefiller materials include silica, alumina, fumed carbon, carbon black,graphite, mica, titanium dioxide, meta-silicate, calcium silicate,kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solidglass, and any combination thereof.

Specific examples of suitable LCM particulates may include, but not belimited to, BARACARB® particulates (ground marble, available fromHalliburton Energy Services, Inc.) including BARACARB® 5, BARACARB® 25,BARACARB® 150, BARACARB® 600, BARACARB® 1200; STEELSEAL® particulates(resilient graphitic carbon, available from Halliburton Energy Services,Inc.) including STEELSEAL® 50, STEELSEAL® 150, STEELSEAL® 400 andSTEELSEAL® 1000; WALL-NUT® particulates (ground walnut shells, availablefrom Halliburton Energy Services, Inc.) including WALL-NUT® coarse,WALL-NUT® medium, and WALL-NUT® fine; BARAPLUG® (sized salt, availablefrom Halliburton Energy Services, Inc.) including BARAPLUG® 20,BARAPLUG® 50, and BARAPLUG® 3/300; BARAFLAKE® (flake calcium carbonate,available from Halliburton Energy Services, Inc.); and the like; and anycombination thereof.

Examples of suitable LCM fibers may include, but not be limited to,fibers of cellulose including viscose cellulosic fibers, oil coatedcellulosic fibers, and fibers derived from a plant product like paperfibers; carbon including carbon fibers; melt-processed inorganic fibersincluding basalt fibers, woolastonite fibers, non-amorphous metallicfibers, metal oxide fibers, mixed metal oxide fibers, ceramic fibers,and glass fibers; polymeric fibers including polypropylene fibers andpoly(acrylic nitrile) fibers; metal oxide fibers; mixed metal oxidefibers; and the like; and any combination thereof. Examples may alsoinclude, but not be limited to, PAN fibers, i.e., carbon fibers derivedfrom poly(acrylonitrile); PANEX® fibers (carbon fibers, available fromZoltek) including PANEX® 32, PANEX® 35-0.125″, and PANEX® 35-0.25″;PANOX® (oxidized PAN fibers, available from SGL Group); rayon fibersincluding BDF™ 456 (rayon fibers, available from Halliburton EnergyServices, Inc.); poly(lactide) (“PLA”) fibers; alumina fibers;cellulosic fibers; BAROFIBRE® fibers including BAROFIBRE® and BAROFIBRE®C (cellulosic fiber, available from Halliburton Energy Services, Inc.);and the like; and any combination thereof.

In some embodiments, LCM particulates and/or fibers may comprise adegradable material. Nonlimiting examples of suitable degradablematerials that may be used in the present invention include, but are notlimited to, degradable polymers (crosslinked or otherwise), dehydratedcompounds, and/or mixtures of the two. In choosing the appropriatedegradable material, one should consider the degradation products thatwill result. As for degradable polymers, a polymer is considered to be“degradable” herein if the degradation is due to, inter alia, chemicaland/or radical process such as hydrolysis, oxidation, enzymaticdegradation, or UV radiation. Polymers may be homopolymers, random,linear, crosslinked, block, graft, and star- and hyper-branched. Suchsuitable polymers may be prepared by polycondensation reactions,ring-opening polymerizations, free radical polymerizations, anionicpolymerizations, carbocationic polymerizations, coordinativering-opening polymerization, and any other suitable process. Specificexamples of suitable polymers include polysaccharides such as dextran orcellulose; chitin; chitosan; proteins; orthoesters; aliphaticpolyesters; poly(lactide); poly(glycolide); poly(ε-caprolactone);poly(hydroxybutyrate); poly(anhydrides); aliphatic polycarbonates;poly(orthoethers); poly(amino acids); poly(ethylene oxide);polyphosphazenes; and any combination thereof. Of these suitablepolymers, aliphatic polyesters and polyanhydrides are preferred.

Dehydrated compounds may be used in accordance with the presentinvention as a degradable solid particulate. A dehydrated compound issuitable for use in the present invention if it will degrade over timeas it is rehydrated. For example, particulate solid anhydrous boratematerial that degrades over time may be suitable. Specific examples ofparticulate solid anhydrous borate materials that may be used include,but are not limited to, anhydrous sodium tetraborate (also known asanhydrous borax) and anhydrous boric acid.

Degradable materials may also be combined or blended. One example of asuitable blend of materials is a mixture of poly(lactic acid) and sodiumborate where the mixing of an acid and base could result in a neutralsolution where this is desirable. Another example would include a blendof poly(lactic acid) and boric oxide, a blend of calcium carbonate andpoly(lactic) acid, a blend of magnesium oxide and poly(lactic) acid, andthe like. In certain preferred embodiments, the degradable material iscalcium carbonate plus poly(lactic) acid. Where a mixture includingpoly(lactic) acid is used, in certain preferred embodiments thepoly(lactic) acid is present in the mixture in a stoichiometric amount,e.g., where a mixture of calcium carbonate and poly(lactic) acid isused, the mixture comprises two poly(lactic) acid units for each calciumcarbonate unit. Other blends that undergo an irreversible degradationmay also be suitable, if the products of the degradation do notundesirably interfere with either the conductivity of the filter cake orwith the production of any of the fluids from the subterraneanformation.

In some embodiments, the concentration of the particles in a drillingfluid described herein may range from a lower limit of about 0.01 poundsper barrel (“PPB”), 0.05 PPB, 0.1 PPB, 0.5 PPB, 1 PPB, 3 PPB, 5 PPB, 10PPB, 25 PPB, or 50 PPB to an upper limit of about 150 PPB, 100 PPB, 75PPB, 50 PPB, 25 PPB, 10 PPB, 5 PPB, 4 PPB, 3 PPB, 2 PPB, 1 PPB, or 0.5PPB, and wherein the concentration may range from any lower limit to anyupper limit and encompass any subset therebetween.

Suitable base fluids for use in conjunction with embodiments describedherein may include, but not be limited to, oil-based fluids,aqueous-based fluids, aqueous-miscible fluids, water-in-oil emulsions,or oil-in-water emulsions. Suitable oil-based fluids may includealkanes, olefins, aromatic organic compounds, cyclic alkanes, paraffins,diesel fluids, mineral oils, desulfurized hydrogenated kerosenes, andany combination thereof. Suitable aqueous-based fluids may include freshwater, saltwater (e.g., water containing one or more salts dissolvedtherein), brine (e.g., saturated salt water), seawater, and anycombination thereof. Suitable aqueous-miscible fluids may include, butnot be limited to, alcohols (e.g., methanol, ethanol, n-propanol,isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol),glycerins, glycols (e.g., polyglycols, propylene glycol, and ethyleneglycol), polyglycol amines, polyols, any derivative thereof, any incombination with salts (e.g., sodium chloride, calcium chloride, calciumbromide, zinc bromide, potassium carbonate, sodium formate, potassiumformate, cesium formate, sodium acetate, potassium acetate, calciumacetate, ammonium acetate, ammonium chloride, ammonium bromide, sodiumnitrate, potassium nitrate, ammonium nitrate, ammonium sulfate, calciumnitrate, sodium carbonate, and potassium carbonate), any in combinationwith an aqueous-based fluid, and any combination thereof. Suitablewater-in-oil emulsions, also known as invert emulsions, may have anoil-to-water ratio from a lower limit of greater than about 50:50,55:45, 60:40, 65:35, 70:30, 75:25, or 80:20 to an upper limit of lessthan about 100:0, 95:5, 90:10, 85:15, 80:20, 75:25, 70:30, or 65:35 byvolume in the base fluid, where the amount may range from any lowerlimit to any upper limit and encompass any subset therebetween. Itshould be noted that for water-in-oil and oil-in-water emulsions, anymixture of the above may be used including the water being and/orcomprising an aqueous-miscible fluid.

Unless otherwise indicated, all numbers expressing quantities ofingredients, properties such as specific gravity, reaction conditions,and so forth used in the present specification and associated claims areto be understood as being modified in all instances by the term “about.”Accordingly, unless indicated to the contrary, the numerical parametersset forth in the following specification and attached claims areapproximations that may vary depending upon the desired propertiessought to be obtained by the embodiments of the present invention. Atthe very least, and not as an attempt to limit the application of thedoctrine of equivalents to the scope of the claim, each numericalparameter should at least be construed in light of the number ofreported significant digits and by applying ordinary roundingtechniques. Further, when “about” is provided at the beginning of anumerical list, “about” modifies each number of the numerical list. Itshould be noted that in some numerical listings of ranges, some lowerlimits listed may be greater than some upper limits listed. One skilledin the art will recognize that the selected subset will require theselection of an upper limit in excess of the selected lower limit.

With reference to FIG. 4, some embodiments described herein may includea wellbore drilling assembly 100. It should be noted that while FIG. 4generally depicts a land-based drilling assembly, those skilled in theart will readily recognize that the principles described herein areequally applicable to subsea drilling operations that employ floating orsea-based platforms and rigs, without departing from the scope of thedisclosure.

As illustrated, the drilling assembly 100 may include a drillingplatform 102 that supports a derrick 104 having a traveling block 106for raising and lowering a drill string 108. The drill string 108 mayinclude, but is not limited to, drill pipe and coiled tubing, asgenerally known to those skilled in the art. A kelly 110 supports thedrill string 108 as it is lowered through a rotary table 112. A drillbit 114 is attached to the distal end of the drill string 108 and isdriven either by a downhole motor and/or via rotation of the drillstring 108 from the well surface. As the bit 114 rotates, it creates awellbore 116 that penetrates various subterranean formations 118.

A pump 120 (e.g., a mud pump) circulates drilling fluid 122 through afeed pipe 124 and to the kelly 110, which conveys the drilling fluid 122downhole through the interior of the drill string 108 and through one ormore orifices in the drill bit 114. The drilling fluid 122 is thencirculated back to the surface via an annulus 126 defined between thedrill string 108 and the walls of the wellbore 116. At the surface, therecirculated or spent drilling fluid 122 exits the annulus 126 and maybe conveyed to one or more fluid processing unit(s) 128 via aninterconnecting flow line 130. After passing through the fluidprocessing unit(s) 128, a “cleaned” drilling fluid 122 is deposited intoa nearby retention pit 132 (i.e., a mud pit). While illustrated as beingarranged at the outlet of the wellbore 116 via the annulus 126, thoseskilled in the art will readily appreciate that the fluid processingunit(s) 128 may be arranged at any other location in the drillingassembly 100 to facilitate its proper function, without departing fromthe scope of the scope of the disclosure.

The replenishment particles may be added to the drilling fluid 122 via amixing hopper 134 communicably coupled to or otherwise in fluidcommunication with the retention pit 132. The mixing hopper 134 mayinclude, but is not limited to, mixers and related mixing equipmentknown to those skilled in the art. In other embodiments, however, thereplenishment particles may be added to the drilling fluid 122 at anyother location in the drilling assembly 100. In at least one embodiment,for example, there could be more than one retention pit 132, such asmultiple retention pits 132 in series. Moreover, the retention pit 132may be representative of one or more fluid storage facilities and/orunits where the particles disclosed herein may be stored, reconditioned,and/or regulated until added to the drilling fluid 122.

The fluid processing unit(s) 128 may include, but is not limited to, oneor more of a shaker (e.g., shale shaker), a centrifuge, a hydrocyclone,a separator (including magnetic and electrical separators), a desilter,a desander, a separator, a filter (e.g., diatomaceous earth filters), aheat exchanger, any fluid reclamation equipment. The fluid processingunit(s) 128 may further include one or more sensors, gauges, pumps,compressors, and the like used to store, monitor, regulate, and/orrecondition the particles described herein.

Some embodiments disclosed herein include: a method that includescirculating a drilling fluid comprising a base fluid and a plurality ofparticles through a wellbore penetrating a subterranean formation;passing the drilling fluid over a screen having a mesh size, therebyseparating the plurality of particles into screened particles having adiameter greater than or equal to the mesh size and retained particleshaving a diameter smaller than the mesh size; adding a concentration ofreplenishment particles to the drilling fluid that comprises the basefluid and the retained particles, wherein a PSD of the replenishmentparticles has a d25_(REP) greater than or equal to the mesh size; andre-circulating the drilling fluid including the replenishment particlesback into the wellbore. Some embodiments may further include at leastone of the following elements: Element 1: wherein a PSD of the pluralityof particles has a d50_(BS) and a PSD of the retained particles and thereplenishment particles in combination has a d50_(CMB), and wherein thed50_(BS) and the d50_(CMB) differ by less than about 15%; Element 2:wherein a PSD of the plurality of particles has a d25_(BS) and a PSD ofthe retained particles and the replenishment particles in combinationhas a d25_(CMB), and wherein the d25_(BS) and the d25_(CMB) differ byless than about 15%; Element 3: wherein a PSD of the plurality ofparticles has a d75_(BS) and a PSD of the retained particles and thereplenishment particles in combination has a d75_(CMB), and wherein thed75_(BS) and the d75_(CMB) differ by less than 15%; Element 4: wherein aPSD of the plurality of particles has a d50_(BS) and a PSD of theretained particles and the replenishment particles in combination has ad50_(CMB); wherein the d50_(BS) and the d50_(CMB) differ by less thanabout 10%; wherein the PSD of the plurality of particles has a d25_(BS)and the PSD of the retained particles and the replenishment particles incombination has a d25_(CMB); wherein the d25_(BS) and the d25_(CMB)differ by less than about 5%; wherein the PSD of the plurality ofparticles has a d75_(BS) and the PSD of the retained particles and thereplenishment particles in combination has a d75_(CMB); and wherein thed75_(BS) and the d75_(CMB) differ by less than 15%; Element 5: wherein aPSD of the plurality of particles has a d10_(BS) and a PSD of theretained particles and the replenishment particles in combination has ad10_(CMB), and wherein the d10_(BS) and the d10_(CMB) differ by lessthan about 15%; Element 6: wherein a PSD of the plurality of particleshas a d90_(BS) and a PSD of the retained particles and the replenishmentparticles in combination has a d90_(CMB), and wherein the d90_(BS) andthe d90_(CMB) differ by less than 15%; Element 7: wherein a PSD of theplurality of particles has a d50_(BS) and a PSD of the retainedparticles and the replenishment particles in combination has ad50_(CMB); wherein the d50_(BS) and the d50_(CMB) differ by less thanabout 10%; wherein the PSD of the plurality of particles has a d10_(BS)and the PSD of the retained particles and the replenishment particles incombination has a d10_(CMB); wherein the d10_(BS) and the d10_(CMB)differ by less than about 5%; wherein the PSD of the plurality ofparticles has a d90_(BS) and the PSD of the retained particles and thereplenishment particles in combination has a d90_(CMB); and wherein thed90_(BS) and the d90_(CMB) differ by less than 15%; Element 8: wherein aPSD of the screened particles has a d50_(SCR) and the PSD of thereplenishment particles has a d50_(REP), and wherein the d50_(SCR) andthe d50_(REP) differ by less than about 15%; Element 9: wherein a PSD ofthe screened particles has a d25_(SCR), and wherein the d25_(SCR) andthe d25_(REP) differ by less than about 15%; Element 10: wherein a PSDof the screened particles has a d75_(SCR) and the PSD of thereplenishment particles has a d75_(REP), and wherein the d75_(SCR) andthe d75_(REP) differ by less than about 15%; Element 11: wherein a PSDof the screened particles has a d10_(SCR) and the PSD of thereplenishment particles has a d10_(REP), and wherein the d10_(SCR) andthe d10_(REP) differ by less than about 15%; Element 12: wherein a PSDof the screened particles has a d90_(SCR) and the PSD of thereplenishment particles has a d90_(REP), and wherein the d90_(SCR) andthe d90_(REP) differ by less than about 15%; Element 13: wherein a PSDof the screened particles has a d50_(SCR) and the PSD of thereplenishment particles has a d50_(REP); wherein the d50_(SCR) and thed50_(REP) differ by less than about 10%; wherein the PSD of the screenedparticles has a d25_(SCR); wherein the d25_(SCR) and the d25_(REP)differ by less than about 5%; wherein the PSD of the screened particleshas a d75_(SCR) and the PSD of the replenishment particles has ad75_(REP); and wherein the d75_(SCR) and the d75_(REP) differ by lessthan about 15%; Element 14: wherein a PSD of the screened particles hasa d50_(SCR) and the PSD of the replenishment particles has a d50_(REP);wherein the d50_(SCR) and the d50_(REP) differ by less than about 10%;wherein the PSD of the screened particles has a d10_(SCR); wherein thed10_(SCR) and the d10_(REP) differ by less than about 5%; wherein thePSD of the screened particles has a d90_(SCR) and the PSD of thereplenishment particles has a d90_(REP); and wherein the d90_(SCR) andthe d90_(REP) differ by less than about 15%; Element 15: wherein thesteps are performed for several wellbore volumes of the drilling fluid;Element 16: wherein the plurality of particles comprises a first type ofparticle and a second type of particle having different specificgravities; Element 17: wherein the plurality of particles comprises afirst type of particle and a second type of particle having differentcompositions; Element 18: wherein the plurality of particles comprises afirst type of particle that is a low aspect ratio particle and a secondtype of particle that is a fiber; Element 19: wherein the plurality ofparticles comprises at least one of a weighting agent and a lostcirculation material; and Element 20: wherein the mesh size is about 35to about 450 API screen number. Examples of suitable combinations ofelements may include, but are not limited to: Element 1 in combinationwith Element 8; Element 2 in combination with Element 9; Element 3 incombination with Element 10; Element 4 in combination with Element 11;Element 5 in combination with Element 12; Element 6 in combination withElement 13; Element 7 in combination with Element 14; at least two ofElements 1-3 and 5-6 in combination; at least two of Elements 8-10 and12-13 in combination; at least two of Elements 1-3 and 5-6 incombination with at least two of Elements 8-10 and 12-13; at least oneof Elements 16-19 in combination with any of the foregoing; at least twoof Elements 16-19 in combination; Element 20 in combination with any ofthe foregoing; Element 15 in combination with any of the foregoing;Element 20 in combination with one of Elements 1-19; and Element 15 incombination with one of Elements 1-14 and 16-19.

Some embodiments disclosed herein include: a method that includescirculating a drilling fluid comprising a base fluid and a plurality ofparticles through a wellbore penetrating a subterranean formation,wherein the plurality of particles has a multimodal distribution thatincludes a first mode having a first d50 lower than a second d50 of asecond mode, and wherein the first mode has a d75 less than a d25 of thesecond mode; passing the drilling fluid over a screen having a mesh sizebetween the d75 of the first mode and the d25 of the second mode,thereby separating the plurality of particles into screened particleshaving a diameter greater than or equal to the mesh size and retainedparticles having a diameter smaller than the mesh size; adding aconcentration of replenishment particles having a d25 greater than orequal to the mesh size to the drilling fluid that comprises the basefluid and the retained particles; and re-circulating the drilling fluidincluding the replenishment particles back into the wellbore. Someembodiments may further include at least one of the following elements:Element 21: wherein the first mode has a d90 less than a d10 of thesecond mode; Element 22: wherein the mesh size is between a d90 of thefirst mode and a d10 of the second mode; Element 23: wherein thereplenishment particles have a d10 greater than or equal to the meshsize; Element 24: wherein the steps are performed for several wellborevolumes of the drilling fluid; Element 25: wherein the plurality ofparticles comprises a first type of particle and a second type ofparticle having different specific gravities; Element 26: wherein theplurality of particles comprises a first type of particle and a secondtype of particle having different compositions; Element 27: wherein theplurality of particles comprises a first type of particle that is a lowaspect ratio particle and a second type of particle that is a fiber;Element 28: wherein the plurality of particles comprises at least one ofa weighting agent and a lost circulation material; and Element 29:wherein the mesh size is about 35 to about 450 API screen number.Examples of suitable combinations of elements may include, but are notlimited to: at least two of Elements 21-23 in combination; at least twoof Elements 25-28 in combination; at least one of Elements 21-23 incombination with at least one of Elements 25-28; Element 29 incombination with any of the foregoing; Element 24 in combination withany of the foregoing; Element 29 in combination with at least one ofElements 21-23; Element 24 in combination with at least one of Elements21-23; Element 29 in combination with at least one of Elements 25-28;and Element 24 in combination with at least one of Elements 25-28.

Some embodiments disclosed herein include: a method that includescirculating a drilling fluid comprising a base fluid and a plurality ofparticles through a wellbore penetrating a subterranean formation,wherein the plurality of particles has a multimodal distribution thatincludes a first mode having a first d50 lower than a second d50 of asecond mode, and wherein the first mode has a d75 less than a d25 of thesecond mode, and wherein a first type of particle corresponds to thefirst mode and a second type of particle corresponds to the second mode;passing the drilling fluid over a screen having a mesh size between thed75 of the first mode and the d25 of the second mode, thereby removing aportion of the second type of particle; adding a concentration of thesecond type of particle to the drilling fluid; and re-circulating thedrilling fluid including the replenishment particles into the wellbore.Some embodiments may further include at least one of the followingelements: Element 30: wherein the first mode has a d90 less than a d10of the second mode; Element 31: wherein the mesh size is between a d90of the first mode and a d10 of the second mode; Element 32: wherein thesteps are performed for several wellbore volumes of the drilling fluid;Element 33: wherein the plurality of particles comprises a first type ofparticle and a second type of particle having different specificgravities; Element 34: wherein the plurality of particles comprises afirst type of particle and a second type of particle having differentcompositions; Element 35: wherein the plurality of particles comprises afirst type of particle that is a low aspect ratio particle and a secondtype of particle that is a fiber; Element 36: wherein the plurality ofparticles comprises at least one of a weighting agent and a lostcirculation material; and Element 37: wherein the mesh size is about 35to about 450 API screen number. Examples of suitable combinations ofelements may include, but are not limited to: Element 30 and 31 incombination; at least one of Elements 30-31 in combination with at leastone of Elements 33-36; Element 37 in combination with any of theforegoing; Element 32 in combination with any of the foregoing; Element37 in combination with at least one of Elements 30-31; Element 32 incombination with at least one of Elements 30-31; Element 37 incombination with at least one of Elements 33-36; and Element 32 incombination with at least one of Elements 33-36.

One or more illustrative embodiments incorporating the inventionembodiments disclosed herein are presented herein. Not all features of aphysical implementation are described or shown in this application forthe sake of clarity. It is understood that in the development of aphysical embodiment incorporating the embodiments of the presentinvention, numerous implementation-specific decisions must be made toachieve the developer's goals, such as compliance with system-related,business-related, government-related and other constraints, which varyby implementation and from time to time. While a developer's effortsmight be time-consuming, such efforts would be, nevertheless, a routineundertaking for those of ordinary skill the art and having benefit ofthis disclosure.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention. The invention illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces.

The invention claimed is:
 1. A method comprising: circulating a drillingfluid comprising a base fluid and a plurality of particles through awellbore penetrating a subterranean formation, wherein the plurality ofparticles has a multimodal distribution that includes a first modehaving a first d50 lower than a second d50 of a second mode, and whereinthe first mode has a d75 less than a d25 of the second mode, and whereina first type of particle corresponds to the first mode and a second typeof particle corresponds to the second mode; passing the drilling fluidover a screen having a mesh size between the d75 of the first mode andthe d25 of the second mode, thereby removing a portion of the secondtype of particle; adding a concentration of the second type of particleto the drilling fluid, wherein the second type of particle have a d10greater than or equal to the mesh size of the screen; and then,re-circulating the drilling fluid into the wellbore.
 2. The method ofclaim 1, wherein the first type of particle and the second type ofparticle have different specific gravities.
 3. The method of claim 1,wherein the first type of particle and the second type of particle havedifferent compositions.
 4. The method of claim 1, wherein the first typeof particle has an aspect ratio less than about 3 and the second type ofparticle is a fiber.
 5. The method of claim 1, wherein the mesh size isabout 35 to about 450 API screen number.
 6. The method of claim 1,wherein the steps are performed for several wellbore volumes of thedrilling fluid.
 7. The method of claim 1, wherein the plurality ofparticles comprises at least one of a weighting agent and a lostcirculation material.
 8. The method of claim 7, wherein the weightingagent is selected from the group consisting of: barite, hematite,ilmenite, galena, manganese oxide, iron oxide, magnesium tetroxide,magnetite, siderite, celesite, dolomite, manganese carbonate, calciumcarbonate, marble, polyethylene, polypropylene, graphitic material,silica, limestone, dolomite, shale, bentonite, kaolinite, sepiolite,illite, hectorite, an organo-clay, and combinations thereof.
 9. Themethod of claim 7, wherein the lost circulation material is selectedfrom the group consisting of: sand, shale, ground marble, bauxite,ceramic material, glass material, metal pellets, high strength syntheticfibers, resilient graphitic carbon, cellulose flakes, wood, resins,polymer materials, polytetrafluoroethylene materials, nut shell pieces,cured resinous particulates comprising nut shell pieces, seed shellpieces, cured resinous particulates comprising seed shell pieces, fruitpit pieces, cured resinous particulates comprising fruit pit pieces, andany combination thereof.
 10. The method of claim 7, wherein the lostcirculation material is a fiber selected from the group consisting of:cellulose fibers; viscose cellulosic fibers; oil coated cellulosicfibers; paper fibers; carbon fibers; basalt fibers; woolastonite fibers;non-amorphous metallic fibers; metal oxide fibers; mixed metal oxidefibers; ceramic fibers; glass fibers; polypropylene fibers; poly(acrylicnitrile) fibers; and any combination thereof.
 11. The method of claim 7,wherein the lost circulation material is degradable.
 12. The method ofclaim 1, wherein the concentration of the particles in a drilling fluiddescribed herein may range from about 0.01 pounds per barrel to about150 pounds per barrel.